Extraction and recovery of crude oil and natural gas from subterranean geological formations and reservoirs requires the drilling of well bores for installation of piping and casings for connecting extraction equipment with the crude oil and/or gas deposits. Drilling such well bores, also commonly referred to as bore holes, requires use of drilling fluids, also called drilling muds, to provide lubrication and cooling for drill bits during drilling operations and to remove rock cuttings and crushed particulates from the drilling faces. Drilling fluids are typically pumped under pressure through a rotating drill pipe to the drilling face, where they flow out of the drill pipe through the drill bits thereby providing cooling to the drill bits, and then return under pressure to the surface between the drill pipe and well casings that are installed as part of the drilling process, thereby removing rock cuttings and particulates from the drilling face and the bits. Drilling fluids are continuously pumped and re-circulated through the drill pipe and casing during drilling operations.
Drilling fluids generally comprise oil or water plus several other components to provide: (i) lubricity and cooling during drilling, and (ii) fluid stabilization through viscosity or gelling when drilling stopped, to maintain the rock cuttings and particulates in suspension. Drilling fluids typically comprise one or more clays for their viscosity properties plus one or more chemicals for one or more of lubrication, cooling, emulsifying, surfaction, rheology modification, “wetting”, controlling the density of the drilling fluids, and to provide thixotropic properties. As drilling continues for extended periods of time, drilling fluids become saturated with rock cuttings particulates, and contaminants such as subterranean water, brines and crude oil released during the drilling process. The lubricity and cooling properties of saturated drilling fluids are significantly reduced, while the presence of cuttings and particulates requires more pumping pressure to maintain recirculation flow rates. Methods and apparatus are available for extending the life of drilling fluids by removal of solids and particulates through screening, coagulation, flocculation, and by dewatering. However, these methods and apparatus are not capable of removing very small particulate materials which continue to accumulate until they saturate the drilling fluids. Such drilling fluids are considered “spent” and are removed from drilling operations.
Recent increased demands for natural gas supplies have resulted in drilling new wells into more technically challenging subterranean deposits, and in reworking of existing wells where down-hole pressure and gas production rates have declined. In both types of situation, a common technique is to fracture reservoir rock with very high pressure water containing very dense granular proppant materials to keep fractures created by the high pressure water propped open after water pressure is reduced. Such fluids are commonly referred to as “fracking fluids”. Such processes are completed by producing the fluids at very high rates to lift excess proppants and particulates produced during the high pressure water flows, to the surface to clear the well bore so that gas flows more freely. The washing-out processes typically are done under high pressure and produce a high-volume three-phase fluid waste flow of gas, liquids, and particulates. Conventional fluid waste flow systems used to separate gas and liquids, typically cannot accommodate the volumes of fluid wastes generated during opening up and conditioning of gas well bores. Consequently, specialized transportable systems and equipment have been developed to sequentially separate gas and then sand from fluid wastes, followed by flocculation of suspended particulates and their removal by centrifugation, resulting in large volumes of fluid wastes that have contain large quantities of very small particles, e.g., in the range of 0.1μ to about 0.5μ. Such fluid wastes are stored for extended periods of time in holding tanks or lagoons to enable settling to occur.
Completion of a drilled well requires removal of a drill string from the bored well hole in combination with pumping of drilling mud to fill the void created as the drill string is moved up. In situations where the drill string is removed more rapidly than the rate of mud pumping, a common result is that the formation fluids and gases (i.e., ground water and other geological fluids) may permeate into the void resulting in significantly decreased bottom hole pressure. The permeation of formation fluids and gases into bore hole voids is commonly called “swabbing” and results in unstable wells that may be dangerous to operate. A common practice to eliminate swabbing during the removal of drill strings is to purge the bore hole by insertion of a paired coiled tubing to about the bottom of the hole after which a clean-out fluid is pumped to the bottom of the hole through one of the coiled tubes while the return clean-out solution is pumped to the surface through the other coiled tube. The return clean-out solution typically comprises formation fluids, drilling mud, clean-out fluid and particulates produced during the drilling process. The return clean-out solution is typically transferred into holding tanks where it is generally stored for periods of time to allow the particulates to settle out, after which the remaining fluids may be clarified by flocculation and centrifugation.
The bore holes of producing gas wells are regularly infiltrated with formation water, clay particulates, and silts over time. These accumulations will increasingly impede and choke-off gas flow, and therefore, producing gas wells are regularly shut-down and cleaned out with swabber devices to remove the formation accumulation mixtures of water, clay and silt. In situations where formation accumulations are significant, the cleaning action of swabber devices is often facilitated by injection of air under pressure by coiled tubing. Similar issues encountered with drilling and well completion, are also associated with handling and disposal of the formation fluid wastes removed from producing gas wells during routine maintenance with swabber devices and coiled tubing. The frequency of production gas well maintenance with swabbers and coiled tubing is site-specific and dependent on the geological properties, and is scheduled on a monthly, or quarterly or semi-annual basis to ensure sustained high-volume production.
Considerable volumes of spent drilling fluids, fracking fluids, and return clean-out solutions accumulate during installation and operation of a well bore, and even greater volumes of fluid wastes are generated during regular swabber and coiled tubing maintenance of production gas wells. These fluid wastes are consequently stored onsite in holding tanks for extended periods of time to enable at least some of the small particulate materials to settle to the bottom of the holding tanks It is common practice to dewater spent drilling fluids by centrifugation to further remove the small particulate solids. However, the waste slurry materials produced are still very fluid and flowable. Waste slurries recovered by settling and/or dewatering spent drilling fluids commonly have high levels of heavy metals and other toxic contaminants, and consequently, their disposal is strictly regulated by various Government agencies. Most regulatory waste disposal requirements stipulate that such liquid wastes must be solidified prior to their cartage from the drilling/waste treatment sites. Elaborate systems and equipment have been developed to mix dry materials into drilling fluid waste slurries to produce agglomerates that can be further dried into bulk materials that can be loaded and transported with conventional aggregate handling equipment. Such systems require considerable infrastructure and capital investment to process the spent drilling fluid outputs from drilling sites.